Expert-Based Methodology for Primary Drainage Capillary Pressure Measurements and Modeling

Abstract

Abstract Primary drainage capillary pressure (Pc) data are key to determining hydrocarbons-in-place. In this paper, a methodology will be described that can be used by practicing engineers and geologists to obtain high quality Pc data, and to analyze those data to make accurate calculations of hydrocarbon-in-place. The steps in the methodology include:Determine the appropriate Pc measurement technique and experimental conditions in order to obtain reliable data for the specific reservoir and rock type.Determine the quantity of data required to sufficiently characterize important facies or rock-types.Analyze the data from various sources, test methods and conditions for quality and consistency.Use an appropriate grouping technique to correlate the Pc data for each rock type. These grouping techniques include J-function-, permeability-, porosity-, or grain density-based correlations.Scale the laboratory data to reservoir conditions, based on the IFT and the contact angle for laboratory and reservoir fluids and the maximum capillary pressure needed to cover the reservoir relief.Model capillary pressure for use in geologic models and reservoir simulation.Integrate the data with other data sources (wireline resistivity data; Dean Stark saturation measurements of core taken with oil-based mud). This methodology is based on the experience gained by measurement and modeling of several thousand capillary pressure data sets from carbonate and clastic reservoir rocks. The methodology can be used for measuring and modeling capillary pressure in a more efficient and reliable way. Introduction In geologic models, each reservoir rock type is sub-classified into facies, based on depositional environment, lithology, and log signature1. Each facies is then quantified in terms of petrology, routine, and special core analysis. The facies effectively subdivide the body or reservoir rocks into groups that display meaningful trends in the petrophysical properties of porosity, permeability, capillary pressure, relative permeability, and formation compressibility. Reservoir facies provide the critical relationship among reservoir lithology, petrophysical properties, and wire-line signature. These quantitative geologic models and reservoir facies are used in virtually every phase of reservoir evaluation and reservoir management. Capillary Pressure Fundamental Concepts The fundamental equation that relates capillary pressure to the pore throat size of a porous medium and the fluids in the pores is:Equation 1 where,Pc = capillary pressure, dynes/cm2r = the pore throat radius, cm.s = interfacial tension between the fluid phases, dynes/cm?=contact angle between the solid surface and the fluid-fluid or gas-fluid interface, degrees. Equation (1) indicates the inverse relationship between pore throat size and capillary pressure. The equation also shows the absence of capillary pressure when the interfacial tension between fluid phases approaches zero. The classification of capillary pressure data based on geological facies is related to the variation of pore throat / pore body size distribution associated with each facies.